Energy Transfer LP Common Units representing limited partner interests 2026 Q2 Earnings Call

Please go ahead. Thank you, operator, and good morning everyone, and welcome to the Energy Transfer second quarter 2026 earnings call.

I'm also joined today by Mackie McCrea, Dylan Bramhall, and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully you saw the press release we issued earlier this morning. As a reminder, our earnings release contains an update to guidance and a thorough MD&A that goes through the segment results in detail. We encourage everyone to look at the release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more details in our Form 10-Q for the quarter ended June 30, 2026, which we expect to file later this week. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Let's start today with going over our financial results for the second quarter of 2026. We generated adjusted EBITDA of approximately $5.1 billion compared to approximately $3.9 billion for the second quarter of last year. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2.6 billion compared to approximately $2.0 billion for the second quarter of 2025.

These results were supported by strong performance in all of our business segments, including record midstream gathering volumes, NGL transportation volumes, NGL export volumes, and crude oil transportation volumes for the quarter. For the first half of 2026, we spent approximately $2.6 billion on organic growth capital in the intrastate, midstream, NGL refined products, and interstate segments, excluding SUN and USA Compression CapEx. Turning to our 2026 adjusted EBITDA guidance. Given our continued strong performance in the second quarter across all of our segments, we now expect our full year adjusted EBITDA to range between $18.8 billion and $19.1 billion, which is up approximately a half a billion dollars at the midpoint compared to our guidance range provided on last quarter's earnings call. Let's go to the organic capital guidance.

We now expect our 2026 organic growth capital expenditures to be between $5.6 billion and $5.9 billion, excluding SUN and USAC. Our growth capital spend remains aligned with the major themes driving our business today, including the increasing demand for natural gas and natural gas infrastructure to support the growing needs for power generation, growth in the Permian, and the growing global demand for natural gas and natural gas liquids. As a reminder, the majority of these growth projects are contracted under long-term commitments and expected to generate mid-teen returns and considerable earnings growth over the next decade or more. Beyond these projects, we have a significant backlog of opportunities that are expected to support future growth. Now turning to our results by segment for the second quarter, I will start with NGL and refined products.

Adjusted EBITDA was approximately $1.3 billion, compared to approximately $1.0 billion for the second quarter of 2025. This increase included record exports out of both our Nederland and Marcus Hook terminals in the second quarter, in part driven by new chilling capacity placed into service last year at Nederland. We saw record throughput across our NGL pipelines related to higher Y-grade and NGL throughput, as well as higher throughput at our Mont Belvieu fractionators. Results for the second quarter also included an increase of $212 million from higher premiums from the sale of NGLs for both export and domestic supply, as well as increased margins from our product optimization and blending operations. This also included gains related to our NGL refined products inventory hedges, $27 million of which we anticipate will be offset in the fourth quarter of this year.

For Midstream, adjusted EBITDA was approximately $884 million compared to approximately $768 million for the second quarter of 2025. This was due to record volumes in the Permian Basin, which increased 5% as a result of new processing placed into service and improved plant utilization. We saw an approximate $88 million increase due to higher NGL prices compared to last year. For our Crude Oil segment, adjusted EBITDA was approximately $834 million, compared to approximately $732 million for the second quarter of 2025. During the quarter, we saw continued growth across several of our crude pipelines, terminals, and gathering systems. Results also included an increase of $106 million related to favorable market conditions, including pipeline and export arbitrage, higher crude oil prices, and Strategic Petroleum Reserve activity at our Nederland Terminal.

As a reminder, in the first quarter of this year, we had a benefit of approximately $60 million related to our crude inventory value that was offset by hedge losses in the second quarter. In the Interstate Natural Gas Segment, adjusted EBITDA was approximately $481 million compared to approximately $470 million for the second quarter of 2025. This increase was primarily due to increased parking, storage, and liquids revenue, as well as higher contracted volumes and utilization on several of our pipelines, including Panhandle Eastern, Transwestern, and Florida Gas Transmission. For our Intrastate Natural Gas Segment, adjusted EBITDA was approximately $377 million compared to approximately $284 million in the second quarter of 2025. This was primarily due to an increase of approximately $113 million from wider basis differentials, as well as an increase of approximately $17 million from early volumes during the commissioning of the Hugh Brinson Pipeline.

This quarter's results once again demonstrate the quality of Energy Transfer's asset base and unique operating model, and further strengthen our belief that the market fundamentally underappreciates the value of our business. Turning to an update on some of our major growth projects and starting with the natural gas side of our business, we are pleased to announce that our Hugh Brinson Pipeline is now in commercial service, with progress being made toward placing the full phase 1 capacity of 1.5 Bcf per day in service. Hugh Brinson shipper contracts are coming online in stages based upon the contractually specified effective date in each agreement. We anticipate that Hugh Brinson will be capable of flowing the full phase 1 capacity by September 1st of 2026, assuming pipeline commissioning activities continue to progress as scheduled.

We continue to expect phase 2, which includes additional downstream compression, to be in service in the first quarter of 2027 and to come in under budget. In addition, during the second quarter, we completed another 14-mile lateral off the Hugh Brinson Pipeline in Abilene, Texas, and is now ready for service. During the quarter, we also entered into an agreement with Crusoe to construct the facilities required to provide natural gas to support previously announced 900-megawatt expansion at the AI Factory campus in Abilene, Texas. Separately, we expect to see additional growth opportunities materialize in the region. Next, we're making good progress on our Desert Southwest Pipeline project. Burke recently completed six in-person and two virtual scoping meetings along the proposed pipeline route throughout Texas, New Mexico, and Arizona.

In addition, as a continuation of our comprehensive stakeholder engagement program, our teams continue to actively engage with elected officials, county leadership, landowners, and associated communities along the route, with discussions remaining very positive. On our last call, we announced the Springerville Lateral, which is an approximately 120-mile extension of our existing Transwestern Pipeline and is expected to be in service in the fourth quarter of 2029. This 30-inch pipeline will have a capacity of approximately 625 million cubic feet per day and extend south to natural gas power generation that is expected to replace two coal-fired plants. We have now locked in pipe and compression costs, and outreach is underway with tribal, state, and federal stakeholders. In Oklahoma, the first of our four connections to serve new power plant loads went into service earlier this year.

The next two are ready for service, with the remaining expected to be in service in the fourth quarter of 2028. In total, these will provide approximately 300 million cubic feet per day of new demand growth. In addition, we are finalizing negotiations to serve approximately 250 million cubic feet per day of new power plant demand in Oklahoma. Overall, we're now seeing interest from customers in increasing the commitments that they had previously made for our natural gas services to large data centers and power plants at or near these sites. This includes two customers in Texas who recently added a combined 100 million cubic foot per day to their contracts. We expect this trend to not only continue, but grow in scale.

We're highly confident in our ability to reach FID on many more of these types of opportunities and remain in advanced negotiations with customers to provide significant volumes associated with our natural gas business in Texas, Oklahoma, Arkansas, Louisiana, Ohio, Illinois, and many other states along our pipeline network. Now looking at the Permian processing expansions. Our Mustang Draw I plant was placed into service in June, and we are already running near capacity for our Midland Basin processing complex. We continue to expect our Mustang Draw II plant to be in service in the fourth quarter of this year. Looking at our liquids business, in June, we announced approximately 240,000 barrel per day ethane export expansion at our Nederland Terminal to meet additional customer demand. The project will also provide an incremental 55,000 barrels per day of LPG capacity.